Seismic data acquisition and processing techniques are used to generate a profile (image) of a geophysical structure (subsurface) of the strata underlying the land surface or seafloor. Among other things, seismic data acquisition involves the generation of acoustic waves and the collection of reflected/refracted versions of those acoustic waves to generate the image. This image does not necessarily provide an accurate location for oil and gas reservoirs, but it may suggest, to those trained in the field, the presence or absence of oil and/or gas reservoirs. Thus, providing an improved image of the subsurface in a shorter period of time is an ongoing process in the field of seismic surveying.
Mapping subsurface geology during exploration for oil, gas, and other minerals and fluids uses a form of remote sensing to construct two-dimensional or three-dimensional images of the subsurface. The process is known as seismic surveying.
Four-dimensional images can also be created by comparing two or more 3-D images acquired at different times to look for changes in the subsurface caused by for example gas injection or production.
Looking to FIG. 1, marine seismic data acquisition, as used, for example, for exploration, field development, and/or production monitoring (time lapse), is normally conducted by a tow vessel 102 towing long cables 104, 108, some of them with seismic sensors 106 through the water. These cables are known as “lead-ins” 104 and “streamers” 108 to people skilled in the art. The streamers 108 are equipped with a large number of seismic sensors 106 with which recordings are made from subsurface reflections of acoustic energy that originate from a seismic source 110 as, for example, a pressure source such as air guns, vibrators, etc. towed behind the seismic vessel 102. A towed array can include one or more streamers 108.
Each time a seismic source 110 is activated, it emits a seismic signal that travels downward through the earth, is reflected, and, upon its return, is received by the seismic sensors 106 in the streamer(s) 108. Each streamer 108 contains a plurality of seismic sensors 106 at spaced apart locations. The received signals are recorded by recording devices. Recorded signals from multiple seismic source 110 and seismic sensor 106 combinations are then processed, assembled and/or combined to create a nearly continuous profile of the subsurface that can extend for many miles. In a two-dimensional (2-D) marine seismic survey, the reflected signal is recorded by the seismic sensors 106 on a single streamer 108, whereas in a three-dimensional (3-D) survey a number of streamers 108 are used simultaneously. In simplest terms, a 2-D seismic line can be thought of as a vertical slice of the earth layers directly beneath the streamer 108. A 3-D survey produces a data “cube” or volume that is, at least conceptually, a 3-D picture of the subsurface that lies beneath the survey area. In reality, though, both 2-D and 3-D surveys interrogate some volume of earth lying beneath the area covered by the survey.
A seismic streamer 108 will typically be several kilometers long, and be comprised of several hundred sensors designed to pick up reflected waves from the subsurface. It is normally also equipped with compasses, acoustic pingers 112, depth sensors and other auxiliary units that give continuous location information about heading, position and depth. Furthermore, each streamer is typically equipped with attached units known as birds 114 that control the heading and depth of that streamer 108.
Chapter 1, pages 9-89, of “Seismic Data Processing” by Özdogan Yilmaz, Society of Exploration Geophysicists, 1987, contains general information relating to conventional 2-D processing and its disclosure is incorporated herein by reference. General background information pertaining to 3-D data acquisition and processing may be found in Chapter 6, pages 384-427, of Özdogan Yilmaz.
A seismic trace is usually a digital recording of the acoustic energy that is received or otherwise picked up by one or more seismic sensors 106. Typically, a trace is determined by combining a group of seismic sensors 106 over a certain length, in some examples referred to as a “receiver length” or “group length”. In some examples, a group of seismic sensors 106 is referred to as a “receiver”. In marine seismic, this group length is typically between 3.125 meters and 12.5 meters, but in some examples, a seismic trace can also be a recording of a received seismic signal from one single seismic sensor 106. In some examples, a “seismic sensor” 106 refers to a single seismic sensor 106 or a group of seismic sensors 106 in a streamer 108 (“receiver”).
In seismic acquisition, the location on the surface halfway between the center of the seismic source 110 and the center of the seismic sensor 106 is referred to as a common mid-point (CMP) and is typically shared by numerous pairs of seismic sources 110 and seismic sensors 106. The CMP location of every trace in a seismic survey is tracked and is generally made a part of the trace header information. This allows the seismic information contained within the traces to be later correlated with specific surface and subsurface locations, thereby providing a means for placing and displaying the trace in its correct position.
A problem often encountered during seismic acquisition is that data are sampled irregularly. The reason for this can be streamer 108 and/or source 110 feathering (the streamer is not towed straight through the water due to ocean currents), obstructions that force the vessel 102 to deviate from the desired course and various mishaps result in missing data. This lack of regular sampling is especially problematic in the cross-line direction (perpendicular to the towing direction), where the data is less well sampled compared to the in-line direction.
To compensate for missing data, it is possible in seismic processing to perform data interpolation and regularization. The goal of this is to ensure that all locations in the subsurface are adequately sampled. However, interpolation is normally limited by the Shannon/Nyquist sampling theorem, stating that a function x(t) cannot contain frequencies higher than B hertz, given its sampling factor of 1/(2B) seconds apart. Interpolation beyond Nyquist will, unless some other information is utilized in the process, result in aliased data.
Traditionally, seismic streamers 108 have only contained hydrophone sensors 106 designed to pick up pressure data. However, a recent trend in the industry has been to also include sensors 106 designed to pick up acceleration or pressure gradient/differential data. With the new types of sensors in a seismic streamer, a so called multi-component streamer is created. The main benefit of these new types of sensors 106 (or streamers) is they enable additional information to be derived from the recorded data. The embodiments herein describe the use of the vertical (Vz) and the horizontal (Vy) velocity, acceleration, pressure gradient or differential to facilitate accurate data regularization and interpolation within the measured location (CMP).
Having access to both pressure and pressure gradient data at each sensor location allows for data interpolation and extrapolation beyond the Nyquist limit. Some of these techniques for generating general interpolated/extrapolated data can be found in U.S. Pat. No. 8,396,668 entitled “Marine Seismic Surveying Employing Interpolated Multicomponent Streamer Pressure Data” by J. O. A. Robertsson and incorporated herein by reference, U.S. Pat. No. 7,715,988 entitled “Interpolating and Deghosting Multi-Component Seismic Sensor Data” by J. O. A. Robertsson, P. Caprioli and A. K. Ozdemir and incorporated herein by reference and U.S. Pat. No. 7,523,003 entitled “Time Lapse Marine Seismic Surveying” by J. O. A. Robertsson, L. Canales, C. Kostov, L. Meister, E. J. Muyzert and L. C. Morley and incorporated herein by reference. Further, techniques for predicting data corresponding to source locations other than the source locations at which the source was actuated is described by L. Amundsen, H. Westerdahl and M. Thompson in their U.S. Patent Application Publication number 20110242935 entitled “Method of Providing Seismic Data” and incorporated herein by reference. In general for the aforementioned techniques, seismic data is predicted for locations where seismic data was not sampled and added to the sampled seismic data to create a regularly and uniformly sampled seismic data set.
Accordingly, it would be desirable to provide systems and methods that avoid the afore-described problems and drawbacks associated with interpolating and/or extrapolating seismic data to new locations, but instead provide methods and systems to generate seismic images based on actual seismic data where it was measured.